1. Field of the Invention
This invention relates generally to the prediction of formation temperatures in a subsurface formation and, more particularly, to the prediction of the temperature of a hydrocarbon formation temperature.
2. Description of Related Art
Hydrocarbon fluids, such as oil and natural gas, are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. An understanding of the undisturbed reservoir temperature is desirable for numerous applications involved in the drilling, completion and production of reservoir fluids. These applications may include, for example: drilling fluid and cement slurry design; log interpretations; corrosion tendencies in wellbore tubulars and downhole equipment; hydrocarbon reserve estimation; flow assurance design; and estimations of geothermal energy, etc.
In drilling operations, the formation temperature has a direct bearing on drilling fluid rheology and therefore has to be considered in drilling fluid and wellbore design. The formation temperature directly impacts cement dehydration and cure times, and therefore needs to be considered in the design of casing and cementing programs. The interpretation of electric logs requires accurate formation resistivities, which are dependent on temperature. In production and well-control operations, accurate computations of fluid flow rates are important. Fluid temperature, both as a function of depth and elapsed time, dictates fluid properties such as density and viscosity, and therefore influences the pressure drops and/or the maximum allowable production rates that can be achieved. Flow assurance design considerations, such as hydrate formation and paraffin deposition prevention, depend on an accurate knowledge of the reservoir temperature.
As a wellbore is drilled, a temperature disturbance is introduced by the circulating drilling fluids, thereby cooling the formation around the borehole. The initial undisturbed formation temperature exists only at a certain distance away from the wellbore. During the circulation of fluids, often referred to as xe2x80x9cmudxe2x80x9d, the temperature within the borehole drops and reaches a pseudo-steady state condition in a very short time. After a certain period of time, the temperature within the wellbore during fluid circulation can be considered constant. Earlier studies have indicated that a constant temperature difference between the bottom-hole fluid and wellbore wall is achieved almost immediately and maintained throughout the life of the wellbore fluid circulation process. This means that the heat transmission from the formation to the wellbore during wellbore fluid circulation is a constant heat flux dominated process. Therefore, during mud circulation, the heat transfer between the wellbore and the formation can be described with a constant heat flux solution of an infinite reservoir. See Raymond, L. R.: xe2x80x9cTemperature Distribution in a Circulating Drilling Fluidxe2x80x9d, JPT, March 1969; and Schoeppel, R. J., Bennet, R. E.: xe2x80x9cNumerical Simulation of Borehole and Formation Temperature Distributions While Drilling to Total Depthxe2x80x9d, SPE paper 3364, presented October 1971.
The amount of departure from the undisturbed formation temperature during drilling and completion operations depends upon several factors, such as, the original temperature distribution, the physical properties of the reservoir rock and the drilling/completion fluids. Fluid circulation rates and duration, and the tubular and cementation design used on the well are also factors that influence the temperature profile. Formation temperatures are often estimated by using temperature measurements taken inside the wellbore, often in conjunction with well logging and fluid sampling.
The process of formation fluid sampling typically involves the lowering of a sampling tool into the wellbore. The sampling tool collects one or more samples of formation fluid by the engagement between a probe module of the sampling tool and the wall of the wellbore. Embodiments of sampling tools may comprise more than a single probe, such as with dual-probe or multi-probe modules, enabling the sampling of differing sites within the formation within a single deployment of the sampling tool. There are several commercially available sample tools available, for example the Modular Dynamics Formation Tester (MDT(trademark)) made by Schlumberger, the Reservoir Characterization Instrument (RCISM) from Baker Atlas, and the Reservoir Description Tool (RDT(trademark)) tool made by Halliburton.
The Modular Dynamics Formation Tester (MDT) formation testing tool, owned and provided by Schlumberger operates by creating a pressure differential across an engagement of a probe module with the wellbore to induce formation fluid flow into one or more sample chambers within the sampling tool. This and similar processes are described in U.S. Pat. Nos. 4,860,581; 4,936,139 (both assigned to Schlumberger). Due to the changes in the temperature field surrounding the wellbore discussed above, the temperature data acquired by the MDT is typically lower than the actual static formation temperature, because of short sampling time. One distinct feature of wireline pretest and sampling is that the flow regime is primarily controlled by three-dimensional (3-D) spherical or radial flow where the probe functions as a point sink. Therefore, the specific difficulty in determining the original formation temperature is the calculation of the fluid temperature at the probe during the recording, which is associated with 3-D spherical flow.
Another sampling tool is the Reservoir Characterization Instrument (RCI), provided by Baker Atlas. It can comprise an optical analyzer, named SampleViewSM, that can be used to monitor contamination levels within sample formation fluids pumped through the tool, and can be run with other reservoir characterization sensors. Examples of other reservoir characterization sensors include pressure sensors and sensors that measure the apparent dielectric constant of the sample fluid, thereby distinguishing oil, gas and water within the sample fluids. The quality of a reservoir fluid sample and the time required to acquire the sample can be predicted utilizing a three-dimensional fluid flow simulation model and input data acquired from the RCI, such as formation pressure, formation permeabilities, and formation fluid properties.
Still another sampling tool that can be utilized with the present invention includes the Reservoir Description Tool (RDT) tool manufactured by Halliburton. It can comprise a modular apparatus that uses nuclear magnetic resonance (NMR) techniques for making downhole NMR measurements of the formation fluid samples, as described in U.S. Pat. No. 6,111,408 to Blades et al.
Referring to the attached drawings, FIG. 1 illustrates a prior art representative drilling/production platform 10 having a tubular string 12 extending into a wellbore 14. The wellbore 14 has penetrated subterranean formations 16, and intersects a productive reservoir 18. A casing string 20 lines the well and provides support and isolation of the wellbore 14 from the formations 16 and bodies of water 22. Wellbore drilling or completion fluids 24, commonly referred to as xe2x80x9cmudxe2x80x9d, are typically circulated down the tubular string 12 and up the wellbore 14. The circulation of wellbore fluids 24 results in the cooling of the reservoir 18 around the wellbore 14. Upon the cessation of fluid circulation, the tubing 12 can be removed from the wellbore 14.
FIG. 2 illustrates a prior art representative drilling/production platform 10 having a downhole tool 26 inserted into the wellbore 14 on a wireline 28. The downhole tool 26 can comprise a formation-testing tool capable of collecting one or more samples of formation fluid, such as, for example, the Modular Dynamics Formation Tester (MDT) formation-testing tool. In addition to obtaining a sample of the formation fluid coming from the reservoir 18, the downhole tool 26 may also collect data such as temperature and pressure readings. Embodiments of the downhole tool 26 can be run into the well on a tubing string, slickline, wireline, or by other means of positioning the tool within the reservoir 18. The temperature T of the formation fluids from the reservoir adjacent the wellbore is lower than the original undisturbed temperature of the formation Te, sometimes referred to as the initial or static reservoir temperature or formation temperature. When the circulation of the wellbore fluids 24 is stopped, the wellbore fluid 24 temperature Tm begins to increase due to the influence of the higher temperatures within the reservoir 18.
FIG. 3 illustrates a prior art embodiment of an MDT formation testing tool 30 that can be utilized in both formation fluid sampling and pretest operations. Various pretest operations can involve flowing formation fluids for a desired amount of time to obtain a specific quantity of fluid removal from the formation, or can comprise flowing a well until a desired pressure drawdown has occurred, in order to measure the pressure recovery or buildup rate. The tool 30 comprises a pump 32 that induces flow of reservoir fluid into a fluid probe 46, along a flowline 34, and then out to the wellbore 14. The flow of reservoir fluid can last an extended period of time to reduce contamination and obtain a better quality reservoir fluid sample, or to provide a desired amount of pretest flow prior to a pressure buildup test or other formation analysis. If it is desired to collect a sample, the opening of seal valves 36, 38 divert a portion of the fluid flow into a sample chamber 40. Any initial fluid that is in the sample chamber 40 can be flushed with the formation fluid. A piston 42 within the tool 30 can move and displace fluid from a buffer chamber 44, thus allowing formation fluid to enter the sample chamber 40. The closing of the seal valves 36, 38 contain the fluid sample within the sample chamber 40 for removal from the wellbore 14 and analysis.
The ability to flow the formation fluid prior to taking a sample enables the MDT tool 30 to provide a more representative sample of the formation fluid by minimizing near wellbore factors such as lost drilling fluids and residual drilling mud from contaminating the sample fluids. The MDT tool 30 can comprise a temperature sensor that records the temperature of the reservoir fluids passing through the flowline 34 during the testing time period.
Current methods to determine the initial reservoir temperature are typically based on extrapolated shut-in temperature recordings. These methods typically require long shut-in periods and result in estimates that are lower than the true reservoir temperature. Complete temperature recovery in the area near the wellbore may take anywhere from a few hours to a few months, depending on the formation, well characteristics, and the mud circulating time. Since a long waiting period for complete temperature recovery can result in a significant increase in drilling costs; a less time consuming method is needed to calculate static reservoir temperature using early shut-in and test data.
One embodiment of the present invention is a method of calculating a static formation temperature in a reservoir penetrated by a wellbore. The method comprises estimating the static formation temperature and calculating a formation fluid temperature at the wellbore, the calculation based, in part, on the estimated static formation temperature. The temperature of a sample of formation fluid at the wellbore is measured. The calculated formation fluid temperature at the wellbore is compared with the measured temperature of the sample of formation fluid. The static formation temperature is predicted by altering the estimate of the static formation temperature until an error between the calculated formation fluid temperature at the wellbore and the measured fluid formation temperature is minimized.
An alternate embodiment of the present invention is a method of calculating a static formation temperature in a reservoir penetrated by a wellbore comprising: estimating the static formation temperature in the reservoir and a wellbore fluid temperature. A calculated formation fluid temperature at the wellbore versus time profile is created for fluid removed from the formation by a sink probe, based upon, in part, the estimates of the static formation temperature in the reservoir and the wellbore fluid temperature. The temperature of the formation fluid at the wellbore removed from the formation by the sink probe is measured, and a measured fluid formation temperature at the wellbore versus time profile is created. The measured fluid formation temperature at the wellbore versus time profile is compared to the calculated formation fluid temperature at the wellbore versus time profile. The static formation temperature is predicted by altering the estimates of the static formation temperature in the reservoir and a wellbore fluid temperature until the error between the measured fluid formation temperature at the wellbore versus time profile to the calculated formation fluid temperature at the wellbore versus time profile is minimized.